Hydrocarbon production is usually restricted by excess water production in naturally fractured reservoirs. Polymer gel injection is an efficient method to shut-off fracture conduits in water bearing zones. Efficiency of water shut-off may decrease in time due to several reasons. Well diagnostic methods such as recovery plot, production history plot and decline curve analysis can be used to identify necessity to re-gel the well. Both of the surveillance methods require some sort of analytical modeling and may not identify performance loss in due time. In this study, we propose the use of pressure build up test analysis as diagnostic tool to optimize re-treatment time. To achieve this goal a highly fractured heavy oil reservoir going through polymer injection is modeled using discrete fracture network (DFN) modelling approach where it is used as a tool for providing fracture properties to the dual-porosity fluid flow simulator. DFN model is created by using available fracture parameters. The model is then calibrated by conditioning it to well test data obtained from a heavily fractured field located in South East Turkey. A CMG STARS single well/dualporosity numerical model whose fracture properties are populated by the DFN model results is used to model polymer injection. Once the matches obtained with DFN populated dual porosity model were obtained, several synthetic pressure build up tests were conducted to estimate skin factor as well as permeability which are markers used for regel treatment performance. It was concluded that well test analysis is an efficient tool to estimate the time of re-gel operation.

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